Method for pipeline leak detection

ABSTRACT

A method is disclosed for pipeline leak detection in which a vacuum is maintained in the annulus of a pipe-in-pipe flowline with a vacuum pump having a discharge reservoir which is monitored for the appearance of water and hydrocarbon vapors. In another aspect of the invention pipeline leak detection is accomplished through maintaining a gas at a nominally constant pressure in an annulus of a pipe-in-pipe flowline and monitoring the annulus for pressure increase indicative of water or product intrusion into the annulus.

This application claims benefit of provision application No. 60/009,452,filed Dec. 29, 1995.

BACKGROUND OF THE INVENTION

The present invention relates to a method for monitoring for leaks insubsea pipelines. More particularly, the present invention relates to amethod for monitoring for remote leaks in subsea offshore pipelinesconstructed as a pipe-in-pipe flowline with the product transported inthe inner pipe.

Offshore hydrocarbon recovery operations are increasingly pressing intodeeper water and more remote locations. Here it is very expensive toprovide surface facilities and it is desirable to minimize theserequirements. Often satellite wells are completed subsea and are tied toremote platforms through extended subsea pipelines as a means to reducethe production cost. Even these platforms serving as central hubs in theoffshore infrastructure are provided only the minimal facilitiesrequired for collecting and partially treating the well fluids beforeexporting them toward onshore facilities through yet more subseapipelines. The subsea pipelines, both to and from the platform hubs, arecrucial to this infrastructure. Further, such pipelines are measured inmiles and tens of miles and although it is infrequent, these pipelinesare subject to failure.

Thus, there is a clear need for a dependable and economical means forremotely monitoring for leaks in the pipelines and, in the event that aleak is detected, to determine the location of the leak for evaluationand/or repairs.

SUMMARY OF THE INVENTION

Toward providing these and other advantages, the present invention is amethod for pipeline leak detection in which a vacuum is maintained inthe annulus of a pipe-in-pipe flowline with a vacuum pump having adischarge reservoir which is monitored for the appearance of water andhydrocarbon vapors. In another aspect of the invention pipeline leakdetection is accomplished through maintaining a gas at a nominallyconstant pressure in an annulus of a pipe-in-pipe flowline andmonitoring the annulus for pressure increase indicative of water orproduct intrusion into the annulus.

BRIEF DESCRIPTION OF THE DRAWINGS

The brief description above, as well as further advantages of thepresent invention will be more fully appreciated by reference to thefollowing detailed description of the preferred embodiments which shouldbe read in conjunction with the accompanying drawings in which:

FIG. 1 is a side elevational view of a platform and a satellite subseawell connected by a subsea pipeline;

FIG. 2 is a cross sectional view of a system for direct heating of apipeline in accordance with one embodiment of the present invention;

FIG. 3 is a partially cross sectioned side elevational view of the pipeinsulating joint assembly of the embodiment of FIG. 2;

FIG. 4 is an axial cross sectional view of the centralizer of theembodiment of FIG. 2, taken at line 4—4 of FIG. 2;

FIG. 4A is a longitudinal cross sectional view of the centralizer ofFIG. 2, taken at line 4A—4A of FIG. 4;

FIG. 5 is an axial cross sectional view of a thermal insulator of theembodiment of the present invention of FIG. 2, taken at line 5—5 in FIG.2;

FIG. 6 is a longitudinal cross sectional view of the pipeline walls andthe annulus in accordance with an embodiment of the present invention;

FIGS. 7A-7D illustrate a progression of side elevational views of amethod for installing the pipe-in-pipe direct heating system of thepresent invention; and

FIG. 8 is a partially sectioned isometric view of an alternateembodiment of a centralizer.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 1 illustrates the environment of the present invention. Here aremote sateffite well 12 is connected to platform 14 with subseapipeline 10 which is provided with a system 10A for direct electricheating in accordance with the present invention. Subsea pipeline 10 isbrought to surface facilities 16 on platform 14 through import riser 18.In this illustration, surface facilities 16 include initial treatmentfacilities 22 as well as a power source, electrical generator 24. Insimilar fashion, an export riser 20 leads to a continuation of thepipeline 10 to shore facilities (not shown). It is important to notethat subsea pipeline connecting satellite well 12 to its first treatmentfacility on the platform may be 20 to 40 or more miles long. Further,the pipeline is extremely inaccessible, resting on the seabed 26 thatmay be a half mile or more below the surface 28 of the ocean.

Components of the well fluids produced may be easily transportedimmediately at subsea well 12 where they retain the formationtemperatures that often range from 150-180 degrees Fahrenheit. However,once produced, they have a long journey through a pipeline in arelatively cold environment. Even in relatively warm oceans such as theGulf of Mexico, the ocean temperature at pipeline depth may be as coldas 40 degrees Fahrenheit or so. Unchecked, the heat loss across thistemperature gradient over this long journey would easily cause theformation of hydrates and the precipitation of paraffins causing thepipeline flow area to become constricted or even to plug. Also, thefluid viscosities of some of the heavier crude oils are adverselyimpacted by low temperatures even before hydrates or paraffins become aproblem. Further, upon occasion it is necessary to work over the well orto take the platform out of service for a period of time. In suchinstances, the pipeline is shut-in and flow ceases for a period,allowing the entire pipeline to cool to the seawater temperature.

These are the challenges of the present invention, to provide for directheating along the length of the pipeline to prevent, or even reverse,hydrate formation and paraffin precipitation inside the pipeline, and toenhance the flow of viscous crudes.

FIG. 2 is a close up view of the direct electric pipeline heating system10A. Pipeline 10 is shown to be a pipe-in-pipe flowline 30 having anelectrically conductive carrier or outer pipe 32 and an electricallyconductive product flowline or inner pipe 34 arranged longitudinally andsubstantially concentrically within the outer pipe. An annulus 36 isdefined between the inner and outer pipes.

The first end or platform end of pipe-in-pipe flowline 30 is providedwith a pipe insulating joint assembly 38 which structurally joins, butelectrically insulates the inner and outer pipes. The first end of thepipeline is terminated at the surface facilities 16 of platform 14 (seeFIG. 1). Returning to FIG. 2, an electrical power input 40 is connectedacross inner pipe 34 and outer pipe 32. Here a first terminal 44A isprovided for power input to the outer pipe 32 and a second terminal 44Bis provided by an electrical penetrator 44C for power input to the innerpipe 34. The power input could be a DC source, but is here illustratedas an AC source interfacing through a transformer 42 having a primarycoil 42A connected to the generator and a secondary coil 42B connectedacross the first and second terminals.

Thus pipe-in-pipe flowline 30 serves as a power transmission line, withthe circuit completed by an electrical pathway connecting the inner andouter pipes at the second or remote end of the pipeline. In transmittingthis power, the entire length of pipe-in-pipe flowline 30 serves as anelectrical heater. Heat is produced by the electrical power loss fromthe current flow through the pipe-in-pipe flowline. For AC, this heatingis due to a combination of interacting effects, including electricalresistance effects, magnetic effects (including magnetic hysteresis andeddy currents) and electromagnetic effects (including the skin effectand proximity effect).

In FIG. 2, the connection 46 for this pathway joining the inner andouter pipes is provided by electrically conductive bulkhead 46A.Alternatively, the pathway could be through an electrical device 48 asillustrated schematically in FIG. 1. This latter embodiment wouldprovide another insulating joint assembly 38 at the second end of thepipeline with terminals 44A and 44B (see FIG. 2) to serve as a powertakeout 46B at the subsea wellhead end of pipeline 10. Remote devices atthe wellhead can thus be conveniently supplied with electrical power toperform such operations as boosting the well fluids pressure with a pumpat the wellhead or preheating the produced fluids as they enter thepipeline. Further, power provided at the wellhead can be transporteddownhole, e.g., to drive a submersible pump in the wellbore or to heatthe downhole tubing string.

It is necessary that inner pipe 34 be electrically isolated from outerpipe 32 along the entire length of pipe-in-pipe flowline 30. Directcontact is prevented with a plurality of electrically insulativecentralizers 50 spaced at frequent intervals along annulus 36. However,it is also necessary to take steps to prevent arcing and otherelectrical discharges across the annulus. These steps may includecareful quality control measures to prevent water and debris fromentering the annulus, removing any sharp points or edges protruding intothe annulus, providing an arc-resistant coating 52 on the outside ofinner pipe 34, and providing a liner 54 at the power input andinsulating joint assembly 38.

It is also useful to remove water from the annulus. This may beaccomplished by forcing dry air or dry nitrogen through the annulus, oralternatively, by evacuating the annulus with a vacuum pump 56. Onceevacuated, the annulus may be maintained under vacuum as part of athermal insulation program or as part of a leak detection program asdiscussed later. Alternatively, it may be desired, after evacuating theannulus, to inject an arc-suppressing gas into the annulus such asSulphur Hexafloride (SF₆) which is shown available in a reservoir 58 inFIG. 2.

Even though direct electric heating is supplied along the length of thepipeline, appropriate steps are taken in the illustrated embodiments tolimit the heat loss from the pipeline to the environment. The amount ofelectrical power required to maintain the inner pipe and contents at agiven temperature is minimized by minimizing the heat losses in thesystem. Direct conductive heat transfer is limited by selectingmaterials for centralizers 50 that are thermally insulative as well aselectrically insulative, and by properly selecting the centralizerlength and the spacing between centralizers. Heat loss throughconvection can be reduced by maintaining the annulus under a vacuum, asdiscussed above, or by providing insulation panels 60 betweencentralizers 50. Radiant heat loss is reduced significantly by placing alow emissivity coating, such as an aluminum-coated mylar film, on innerpipe 34, but may already be a small factor if insulative panels 60 areused. Further, it should be noted that Sulphur Hexafloride (SF₆) canprovide thermal insulation as well arc-suppression benefits. It may alsobe useful to hold the vacuum in the annulus for an extended period,e.g., over several weeks, before injecting the Sulphur Hexafloride (SF₆)in order to remove air defused into the open cells of the low densityplastic foam of insulation panels 60.

FIG. 3 illustrates an insulated joint assembly 38 in greater detail. Theinner pipe is isolated from the outer pipe by annular rings 62 formedfrom a material that is both strong and very resistant to electricalbreakdown, e.g., a suitable epoxy or zirconia. Other annular spaces 63within the insulating joint 38 are filled with similar high strength,electrically resistant materials. Liner 54 is bonded over each side ofinsulator interface 64 to prevent electrical breakdown due to brine inthe well fluids. This figure also illustrates an electrical terminal 46connected to the inner pipe by an electrical penetrator 46C which passesthrough an electrically insulated, vacuum-tight port 46D. In thisembodiment the liner 54 terminates in a swage ring liner termination 66.

FIGS. 4-4A illustrate one embodiment of insulated centralizer 50. Herecentralizers are molded and/or machined from a strong, non-charringplastic or char-resistant such as Nylon or a polyacetal plastic such asthat marketed under the name Delrin to form collars 50A that are securedabout inner pipe 34 with non-conductive elements such as non-metallicsocket head cap screws 68. In this embodiment water and solid intrusionwithin the centralizer is blocked to prevent electrical discharge. Arubber liner 70 is secured about inner pipe 34 and collars 50A areplaced around the rubber liner which is captured within shoulders 80. Akey 72 on the collar fits within the gap 74 in the rubber liner. Thiskey is opposite the open side or slit 76 of the collar and prevents anyalignment of gap 74 and slit 76. Further, it may be desirable tocompletely seal the slit with a silicon adhesive caulk or a silicongasket. Such precautions may be desirable to prevent contaminants fromforming a bridge from the inner pipe to the outside of centralizer 50which is in contact with outer pipe 32. In a another embodiment, therubber liner 70 overlaps when wrapped around the inner pipe. This lineris taped in place and halves of a “keyless,” two-piece collar 50A arethen clamped over the rubber liner and tightened down with opposingscrews 68.

FIG. 8 illustrates another embodiment of the insulated centralizer 50.Here centralizer body 50B and tapered sleeve 78 are molded and/ormachined as before from a strong, non-charring or char-resistant plasticsuch as Nylon or Delrin. Centralizer is assembled by placing the twohalves 78A and 78B of the tapered sleeve around the inner pipe 34 andcoating 52. Then the tapered inner surface of the centralizer 50B isforced longitudinally over the tapered outer surface of the sleeve 78,providing an interference fit which secures the sleeve to the pipe 34.Finally, centralizer body 50B is secured to the tapered sleeve 78 byadhesive bonding or by welding of the plastic parts. Precautions toprevent arcing due to contaminants are fewer and less critical with thisembodiment, since the centralizer does not have any radial slits as withthe other embodiments.

Although, the inner pipe 34 is substantially aligned coaxially with theouter pipe 32 with centralizers 50, it is desired to provide a flow pathin the form of gaps or longitudinal channels between centralizers 50 andthe outer pipe 32, through which the annulus can be evacuated or filledwith an arc-suppressing gas as discussed above. This flow path may becreated by making the outer diameter of the centralizers 50 a littlesmaller (by 0.2 to 0.4 inch, say) than the inner diameter of the outerpipe 32, or by forming longitudinal grooves or scallops (not shown) intothe outer surfaces of the centralizers 50.

The centralizers are placed at longitudinal intervals which will preventthe inner pipe from buckling due to installation or operational loads.In practice, this interval between centralizers may be about 10 to 20feet. The inner pipe is thus prevented from moving into such proximitywith the outer pipe that an arc or direct contact might result.

FIG. 5 illustrates a cross section through pipe-in-pipe flowline 30 at aring of insulated panels 60. Describing the components from the insideout, the product flowline or inner pipe 34 is provided a smooth,continuous inner surface that does not promote fouling and is piggableas may be necessary to clear the line or for other purposes. The outsideof inner pipe 34 is provided a thick coating 52 of an arc-resistantmaterial such as high density polyethylene or polypropylene which may beextruded over an initial corrosion resistant coating. A pair of lowdensity plastic foam insulation panels of a material such aspolyisocyanurate are assembled about inner pipe 34 for insulativecoverage between centralizers 50 (see FIG. 2). These may be convenientlyhandled in 4- to 6-foot long sections or so. These panels are glued ortaped in place with electrically insulative, arc-resistant materialsabout the inner pipe and a seal secured with the abutting centralizers50. This low density foam is partially open celled, so that evacuationof the annulus, then filling it with Sulphur Hexafloride (SF₆) injectionoperations will tend to fill the voids with arc-suppressing, thermallyinsulative gas. Further, the surface of panels 60 may be coated forincreased char-resistance. In particular, anti-char coatings such as asilicon rubber based compound marketed by Dow under the name Sylgard maybe used immediately adjacent to centralizers 50. The characteristics ofthe low density plastic foam may also be selected for inhibiting itstendency to crumble and create debris within annulus 36. If desired, analuminized mylar film can be affixed to the outside of the panels, shinyside out, to reduce radiant heat loss.

Further, the seams formed by adjoining pieces of foam insulation couldallow possible contaminants such as pipe scale and/or water to form apath to the inner pipe and result in electrical failure across theannulus. The foam insulation may be conveniently wrapped with anadhesive backed membrane to ensure against this risk. A suitablemembrane is permeable to air and water vapor, allowing their removalfrom the foam under vacuum, but blocking entry of liquid water andsolids such as pipe scale. Tyvek®, a material marketed by DuPont, wouldbe useful for such embodiments.

The interior of outer pipe 32 is preferably treated to prevent theformation of scale which might bridge the annulus or initiate an arc.Such treatment might include a pickling operation with acid and oiltreatments, or blast cleaning followed by internal coating with epoxy ornylon or installation of a liner. If a liner is installed, it couldinclude a mylar film to further limit radiant heat loss.

Finally, the outside of outer pipe 32 will typically be provided with acorrosion resistant coating and cathodic protection as commonly deployedin offshore applications, e.g., a fusion bonded epoxy coating, togetherwith sacrificial anodes spaced at intervals along the pipeline. Further,if DC power transmission is used, the polarity should be such as tofurther cathodically protect the outer pipe.

It should be noted that AC power has several benefits over DC power, andis preferred for this application. First, the power and voltagerequirements for direct electrical heating of the pipeline and powertransmission to the satellite wells is within conventional AC powerengineering limits and is already available on platforms in standard 60Hertz power plant configurations. Although it may be desirable to alterthe frequency in certain applications, the basic power commitments forpipe lengths up to 40 miles, and perhaps more, may be achievable withoutspecial purpose generators. Second, DC power raises significant concernsabout corrosion control for the underwater pipelines, which is not anissue for AC power. Finally, in a pipe-in-pipe flowline, the skin effectand proximity effect associated with AC power cause the current totravel on the outside of inner pipe 34 and the inside of outer pipe 32.See arrows 82 in FIG. 6. Safety is enhanced as almost no voltagepotential is present on the outside of carrier pipe 32.

FIGS. 7A-7D illustrate one method for installation of a pipe-in-pipeflowline suitable for direct electric pipeline heating and other powertransmission to remote subsea wells. In FIG. 7A, Carrier pipe 32A issuspended on end in slips 90 at weld floor 92 of a J-lay installationbarge. Collar/elevator 96A engages shoulder 94 presented on the end ofpipe sections of carrier pipe 32A to secure this suspension. An end of asection of product flowline 34A extends out of carrier pipe section 32A.These pipes are joined together at the terminal end as shown in FIG. 2.Since the centralizers 50 provide substantial lateral support andprevent buckling between outer pipe 32A and inner pipe 34A, thesecentralizers thereby also prevent relative longitudinal movement(sliding) between the two pipes, even when suspended vertically as shownin FIGS. 7A-7D.

Another concentrical arrangement of inner and outer pipe sections 34Band 32B, respectively, is lowered into place for joining into thepipeline while supported by the collar/elevator 96B. The internal plug98 on the upper end of the vertically approaching inner pipe section 34Ballows the inner pipe to extend beneath outer pipe 32B, but not to slidefarther down.

In FIG. 7B, inner pipes 34A and 34B are brought into position and weldedtogether. Special care is taken to prevent the deposition of debris intothe annulus as installation proceeds. The inner pipe weld is coated,e.g., by a shrink sleeve of polyethylene or polypropylene, whichprovides continuity to both corrosion coating and arc-resistant barriercoating 52 on the outside of inner pipe 34.

High temperature thermal insulation material such as mineral wool isplaced in the annulus between the two welds as a protection to otherheat sensitive materials in the annulus. Otherwise, heat might damagemembranes, coatings, and/or insulative foam under the weld, creating acharred material and possible electrical path to the inner pipe. It isconvenient to fabricate and install this char-resistant refractorymaterial as “clamshell” halves similar to the foam insulation. It isonly necessary that this protection extend for a few inches to each sideof the weld.

Then outer pipe 32B is lowered into alignment with outer pipe 32A andwelded into place. See FIG. 7C. An appropriate corrosion coating isapplied to the outer pipe weld, collar/elevator 96A is removed, theassembled pipe-in-pipe section is lowered through the slip untilpipeline is suspended by collar/elevator 96B, and internal plug 98 isremoved. See FIG. 7D. This J-Lay process then repeats with addingsuccessive sections to the pipe-in-pipe flowline 30.

Alternatively, these vertical pipe assembly techniques may be utilizedhorizontally to install pipe-in-pipe flowlines by the S-Lay method. Asanother possible alternative, long sections, e.g., 1500 feet or so, ofinner pipe 34 and outer pipe 32 may be assembled onshore, strungtogether into concentric relation, and sequentially reeled onto a largediameter reel for later installation offshore.

The pipe-in-pipe configuration of subsea pipeline 10 is also useful forleak detection. In embodiments maintaining a vacuum in the annulus, aleak in the outer pipe will manifest as water vapor in vacuum pumpdischarge 56A. See FIG. 2. Pressuring up the annulus with dry air ornitrogen will discharge bubbles 102 to locate the leak, see FIG. 1. Theexact position of the leak could then be pinpointed with an ROVinspection of the exterior of the pipeline, and an external leak repairclamp can be installed at the point of failure to seal the leak. A leakin the inner pipe will be observed as hydrocarbon vapor in the vacuumpump discharge and might be located through use of an inspection pig.Repair of an inner pipe leak will require cutting the pipeline, removalof the damaged section, and re-joining of both outer and inner pipes onthe seafloor with mechanical connections.

Alternately, by maintaining a constant volume charge of arc-suppressinggas such as Sulphur Hexafloride (SF₆) in the annulus of a pipe-in-pipeflowline, any increase in annulus pressure would signal seawaterintrusion through a breach in the carrier pipe. Again, the annulus couldbe pressured up to leave a bubble trail to reveal the location offailure. Further, in the event of any failure of the inner pipeline, theSulphur Hexafloride (SF₆) could be used a as a tracer. The annulus couldbe pressured up incrementally and held, and the appearance of the tracergas at the collection point would be indicative of the pressure at whichthe annulus pressure exceeded the flowline pressure. This thencorrelates roughly to position along the pipeline. Alternatively, thetravel time for a charge of high pressure gas in the annulus to enterthe flowline and appear at a collection point could be correlated toapproximate location along the pipeline.

At commissioning, air and water are removed from the annulus, andarc-suppressing and thermally insulative gas is injected, if desired, asdiscussed above. After connecting the power input to the flowline at theplatform end, the level of electrical power is brought up slowly so thatany arcing initiated by minor debris or contamination might occur withminimal damage. Progress in application of power to the system andresulting temperature increases at both ends of the pipeline would bemonitored carefully. When brought to operational levels, it may bedesired to establish calibration of actual power and voltage input toheating output by placement of thermocouples 100 at appropriatelocations along the pipeline.

In operation, the modified pipe-in-pipe flowline provides convenientpower transmission for direct electric heating of the pipeline and fordriving remote electrical components. The heating is useful forpreventing hydrate formation and paraffin deposition, and for enhancingflow of heavy crudes. This is particularly important while maintainingwell fluids within a shut-in subsea pipeline. It is also useful forreversing blockages caused by hydrate formation and paraffin dispositionat somewhat higher, but nonetheless practical power levels. Further, itshould be noted that pulses and frequency modulation can be carried ascontrol signals along with the power transmission to control componentsat remote satellite subsea wells or the like.

Other modifications, changes and substitutions are intended in theforegoing disclosure and in some instances some features of theinvention will be employed without a corresponding use of otherfeatures. Accordingly, it is appropriate that the appended claims beconstrued broadly and in the manner consistent with the spirit and scopeof the invention herein.

What is claimed is:
 1. A method for pipeline leak detection in extendedsubsea pipelines, comprising: maintaining a vacuum in the annulus of apipe-in-pipe flowline with a vacuum pump having a discharge reservoir;and monitoring the discharge reservoir for the appearance of seawaterleaking into the annulus through an outer pipe and hydrocarbon vaporsleaking into the annulus through an inner pipe.
 2. A method for pipelineleak detection in accordance with claim 1 further comprising: pressuringup the annulus with dry air to discharge air bubbles through a breach inan outer pipe of the pipe-in-pipe flowline upon detecting water vapor inthe vacuum pump discharge reservoir; and monitoring the exterior of thepipeline with an ROV for signs of air bubbles to locate the source ofthe breach of the outer pipe.
 3. A method for pipeline leak detection inaccordance with claim 1 further comprising: pressuring up the annuluswith dry nitrogen to discharge gas bubbles through a breach in an outerpipe of the pipe-in-pipe flowline upon detecting water vapor in thevacuum pump discharge reservoir; and monitoring the exterior of thepipeline with an ROV for signs of gas bubbles to locate the source ofthe breach of the outer pipe.
 4. A method for subsea pipeline leakdetection comprising: maintaining a gas at a nominally constant pressurein an annulus of a pipe-in-pipe flowline; monitoring the annulus forpressure increase indicative of water or product intrusion into theannulus; increasing the annulus pressure with a tracer gas in incrementsmonitored to determine at what pressure the tracer gas appears at theend of the pipeline; and correlating the annulus pressure at which thetracer gas first appeared at the end of the pipeline with the pressuregradient along the pipeline to determine roughly where a breach of theinner pipe is located.
 5. A method for pipeline leak detection inaccordance with claim 4, further comprising: creating a pulse ofpressure with a tracer gas in the annulus and timing the delay until thetracer gas appears at the end of the pipeline; and correlating thetravel time of the tracer gas with the rate of product flow to determineroughly where a breach of the inner pipe is located.